Canada is well-positioned to become a key producer of hydrogen being one of the world’s lowest-cost producers of low-carbon hydrogen. The western provinces, Alberta, British Columbia, and Saskatchewan have the country’s largest CCS resources and reportedly can produce hydrogen at half the wholesale cost of diesel. But if the future of hydrogen production in the west is tied to CCS resources, what are the hurdles to developing projects? Are there cases to be made for the best markets to pursue? Hydrogen and CCS project developers are increasingly expressing a need for more certainty, specifically referring to regulatory constraints.
In TC Energy’s 2022 Investor Day webcast on Nov 29th, Francois Poirier TC Energy President and CEO referred to the company’s interest in developing hydrogen projects calling hydrogen “a very interesting potential asset class for us over the course of the next decade.” Poirier called for an acceleration of regulatory processes to get projects sanctioned in a more efficient manner and referred to regulatory constraints as a challenge. Poirier stated they intend to work with various levels of government to accelerate the regulatory process as it currently takes over 5 years to sanction a project.
In Alberta, the hydrogen roadmap was a step forward by the province to provide more regulatory clarity. It has identified five leading markets for Alberta’s clean hydrogen end-use opportunities including the following sectors:
Invest Canada has identified hydrogen as “a key pillar in decarbonizing the global energy system” which seems to imply the same promotion of hydrogen for the export market as mentioned in the Alberta Hydrogen Roadmap.
However, in terms of markets, hydrogen for export has also come under criticism, as recently as Nov 30, by Nigel Steward, chief scientist at Rio Tinto. In a presentation to investors, Steward criticized the export and shipping of hydrogen over long distances as potentially worse for the climate than burning natural gas and said it was “ currently uneconomic, as well as energy and capital intensive.” He stated Rio Tinto would instead “produce hydrogen where we consume it.” Producing hydrogen close to consumers is practical and appealing to several Canadian hydrogen projects that are currently under development for the industrial process and heating markets.
Devin Lacey, manager, of New Ventures & Emissions at GLJ Ltd says what he is increasingly seeing from project developers is the requirement for market development as well as more certainty regarding regulatory support and clarity. He says the large-scale hydrogen projects that are getting announced and sanctioned in Western Canada and throughout North America are not necessarily targeting the nascent hydrogen end uses- transportation, power generation and heat generation. They are targeting the more mature, de-risked markets, which are essentially the markets that already use hydrogen today. He refers to the “low hanging fruit for developing blue, green and clean hydrogen” to replace existing grey hydrogen.
The existing markets allow the development of a product with more certainty knowing that existing regulation already supports production methods in existing uses. The hydrogen projects that we are seeing from major operators tend to be developing hydrogen with the lower-risk markets in mind.
Air Products’ recently announced hydrogen complex in the Edmonton region is an example of this type of large-scale hydrogen project. The Federal and Alberta governments announced approximately $475 million (CAD) in project funding in November this year according to a company news release.
“They’re able to propose building a large scale project because they are in the Industrial Heartland, and can provide blue hydrogen to mature markets,” Lacey says. “So that’s why they can execute it versus the projects targeting more nascent markets which are more likely to employ a stepped approach.”
Oil refining, bitumen upgrading, ammonia production for fertilizers, chemical production and to a certain extent, the potential for hydrogen blending with natural gas are generally seen as relatively accessible markets for early projects. When it comes to blending hydrogen with natural gas, it is not likely a sustainable, long-term decarbonization solution, but it has great potential for demonstrating the concept of hydrogen utilization, to justify increased production of low-carbon hydrogen, and de-risk early project developments.
Enbridge has a blending demonstration project in Markham Ontario, and it creates an effective end-use market for hydrogen that is being produced through electrolysis. In this case, Enbridge is accessing an existing hydrogen market which is its own gas infrastructure. They’re blending hydrogen and natural gas, distributing it with their gas infrastructure, and decarbonizing approximately 3,500 homes. It embodies the hurdle that hydrogen projects or production projects need to overcome today to develop markets.
However, the two hurdles of regulatory constraints and the need for clarity on a path forward from a regulatory perspective are proving to be time-consuming for projects. For example, a project developer dealing with the provincial government from the earliest stages needs clarity on what is needed in terms of understanding environmental assessment requirements.
A clear understanding of Indigenous and social consultation requirements is also needed because there are already existing frameworks for those requirements in many other established markets (like oil and gas markets). For hydrogen, there’s still some clarity needed on how to go about stakeholder consultation in a fulsome and reliable manner.
“In addition, the safety and regulatory standards that are required in this sort of expanded hydrogen economy are still under development,” Jodi Anhorn, President, and CEO at GLJ adds. “Obviously safety and regulatory standards exist for today’s hydrogen economy and the relatively limited industrial uses that we have for hydrogen today. But if we’re going to start piping pure hydrogen across the province or cross country and if we’re going to start using hydrogen at a refuelling station, there’s a whole new set of safety and regulatory requirements that need to come out. If they aren’t developed relatively soon, and if they’re not clear, then that adds to the market risk that these companies are already concerned about. Development of the safety and regulatory standards that need to be associated with the expanded hydrogen economy is a big task.”
The consensus is that once companies can begin to blend with 5 to 10 per cent hydrogen, it will help to justify the early-stage investment in blue and green hydrogen production. However, it doesn’t promote an established market unless the switch is “flipped” to 100% hydrogen according to Anhorn.
He says this change can not be accomplished until the end users become well-established with more diverse end-use projects. At this stage of development, production and end use must be co-located until it’s time to build out the distribution infrastructure because there is a need to build out supply and demand almost simultaneously.
Of all the western provinces, Alberta leads with a well-developed regulatory environment for oil and gas royalties and rights and a well-established history of oil and gas regulation. But, getting the pore space to sequester the CO2 to form blue hydrogen is currently a challenge, even though there are currently twenty-five CCS/CCUS projects under consideration.
“We’ve been very busy lately because we’ve been working with clients during the pore space application process for CCS hubs or CCUS,” Jodi Anhorn says. “On one hand it is a regulatory hurdle. But on the other hand, the Government of Alberta as of last fall did provide some clarity with the Alberta Carbon Sequestration Tenure Management document. Whether people agree with the process or not, is another story, but at least we have begun the process for submitting full project proposals as it pertains to CCS hubs and they are being reviewed for development now.”
Anhorn agrees with Alberta’s decision when they established that it was the Crown’s responsibility to award the pore space for sequestration. Then they declared they will start awarding it subject to a number of requirements: pore space that’s at least 1,000 meters in depth, no intrusion on existing operations etc. Some may not agree with the length of the checklist that has to be gone through when analyzing project proposals and applications before they could award for status, but at least the process has been established.
“Previously, there wasn’t a clear process for dedicated, large-scale sequestration,” says Devin Lacey. “There were processes for existing schemes like acid gas injection or enhanced oil recovery, but there was no clear process for a megatonne CO2 sequestration project. So as it relates to low carbon hydrogen production in Alberta that requires carbon capture and storage, this is an important step in regulatory clarity in Alberta.”
“Alberta has established not only a solid process for pore space application as it pertains to CCS, but also created an established and functioning carbon credit market, which is a huge driver for CCS & blue hydrogen,” Jodi Anhorn adds.
“So I would say that Alberta kind of ticked those two important boxes and that Alberta is considered a leader on a national scale. But B.C., Saskatchewan, and Manitoba are very much watching what works and what doesn’t work in Alberta and they may not necessarily go the same route. I think it’s probably fair to say that the demand for Alberta to move early was very strong. They responded to a lot of pressure to try to get it right.”
Maureen McCall is an energy professional who writes on issues affecting the energy industry.